By 2004 large Massachusetts power-plants were making progress toward complying with changes in 2001 to state air quality regulations. Data from the U.S. Environmental Protection Agency for 2004 [1] follow:
These are the six large power-plants targeted by a Clean Air campaign during 1997-2001 and subject to revised state emissions limits issued in April, 2001. Electricity is in trillions of watt-hours, and emissions are in thousands of tons. Electricity and emissions are also shown as shares of the totals for all Massachusetts power-plants in 2004. The six large power-plants combined had reduced their total nitrogen oxide emissions to an amount close to the revised standards, based on the amount of electricity generated, and they had completed about half their required reductions in total sulfur dioxide emissions.
Much of the achievement resulted from installation at the Mystic plant in 2002 of new combined-cycle generators fired by natural gas. The Canal plant continued to burn residual fuel oil, and only small parts of upgrades at the four mainly coal-fired plants had been completed. By 2009, remediation of all six plants is scheduled to be finished. If each plant were to meet the state's revised air quality standards on an individual basis, and if electricity generation were to remain unchanged from 2004, results projected for 2009 would be as follows:
Actual results will differ from that projection, because the Mystic plant can be expected to continue operating as it did in 2004, and because the power-plants are allowed to trade allowances for sulfur dioxide emissions. A conservative estimate is that total sulfur dioxide emissions will be about as projected, because of allowance trading, but total nitrogen oxides emissions from the six plants will be about 13,200 tons, reflecting the 2004 Mystic plant emissions instead of the Mystic plant limits.
Thus by 2009 Massachusetts can probably expect that the six large power-plants subject to revised emissions standards, producing about 57 percent of electricity generated in the state, will emit about 52 percent of nitrogen oxides and 86 percent of sulfur dioxide released by all Massachusetts power-plants. Revised standards have been effective in bringing nitrogen oxides emitted from the six plants below average emissions for the state's power industry, but they have not been stringent enough to make similar progress with sulfur dioxide.
Power-plant emissions of nitrogen oxides can be compared with the major source of this pollutant: light-duty vehicles -- automobiles and small trucks. Massachusetts had about 4.65 million registered light-duty vehicles as of 2000 [2]. The U.S. Environmental Protection Agency found nationwide that light-duty vehicles emitted 56.9 million tons of nitrogen oxides in 2002 [3]. The most recent U.S. surveys found 191.0 million light-duty household vehicles [4] and 19.6 million light-duty commercial vehicles [5]. This leads to average emissions of 0.27 tons per vehicle per year. Nitrogen oxides emissions for 2004 from the six large power-plants above were equivalent to emissions from about 75 thousand light-duty vehicles, or about 1.6 percent of the state's light-duty vehicle fleet. From a statewide perspective, sulfur dioxide emissions are the dominant air pollutant from power-plants.
The five large Massachusetts power-plants burning coal and high-sulfur oil will continue to emit much more sulfur dioxide than new coal-fired plants that comply with the Best Available Control Technologies standard, as required by the federal Clean Air Act of 1990. See "Politics of air pollution control, Massachusetts," October 17, 2007. The 2001 initative by Massachusetts to remediate existing power-plants has also resulted in lower standards for pollution reduction than later federal settlements of Clean Air Act enforcement actions. See "Legal victories for cleaner power," October 9, 2007.
Massachusetts communities have been congratulating themselves on recycling solid waste, but some give little care to where recycled material goes. Quite a bit winds up making air pollution. As of 2004 Massachusetts had five "waste to energy" plants burning recycled material and generating 10,000 MWh or more electricity per year per plant. These plants emit very large amounts of nitrogen oxides for the electricity they generate. Data from the U.S. Environmental Protection Agency for 2004 [1] follow:
The five waste-burning plants combined emitted average amounts of sulfur dioxide, compared to electricity they generated, but emitted more than 16 times the 2004 average for state power-plants in nitrogen oxides. While generating just under one percent of the electricity, they were responsible for near one-sixth of all nitrogen oxides emissions from Massachusetts power-plants. Emission controls varied, with SEMASS near twice and Pioneer Valley about three times the Wheelabrator plant nitrogen oxides emissions per unit electricity. Massachusetts waste-burning plants emit as much nitrogen oxides as about 20 thousand average light-duty vehicles.
Like many consumers of petroleum fuel, the Canal plant in Sandwich, MA, may have to buy more lower-sulfur fuel than otherwise preferred to satisfy emission limits. In recent years markets for low-sulfur residual fuels have become supply-limited. Although several advanced processes have been demonstrated for upgrading residuals by removing sulfur, such as TransFining from Trans Ionics of Texas, so far none has achieved widespread use. Among the more stringent regulations in the U.S. is New York City's limit of 0.3 weight percent sulfur for residual fuel oils, which can be met by limited desulfurization of residuals from low-sulfur crude. That is equivalent to about 0.17 pounds sulfur per million Btu. For 2004 data from the Environmental Protection Agency [1] show sulfur dioxide emitted by the Canal plant equivalent to 0.52 pounds sulfur per million Btu, so average sulfur in its fuel oil must have been at least 0.9 weight percent.
The U.S. Environmental Protection Agency publishes periodic reviews and estimates of fuel availability and pricing. Through 2020 the agency estimated that cost per unit heat energy of low-sulfur residual (typically 0.7-1.0 weight percent sulfur) in New England will be at 12 to 13 percent premium over high-sulfur residual (typically 2.2-3.5 percent) [6]. Residual fuels with sulfur content as low as 0.2 percent are available [7] at increasing premiums, still well below premiums of more than 50 percent for distillate fuels.
Escalating costs for petroleum fuels, with inflation-adjusted prices of crude petroleum more than doubling between 2002 and 2007 [8], have apparently led to cutbacks reported at Canal [9]. The plant is said to have produced 1.7 TWh in 2006, less than one-third its 2004 output and only 17 percent of maximum capacity. In April, 2007, owners of the Canal plant, in bankruptcy from July, 2003, to January, 2006, stated they may seek a buyer [10]. Salem Harbor and Brayton Point are reported to have used oil-fired generators at only 5 percent and 1 percent of their capacities in 2006 [9]. No sustained petroleum price decline is foreseen, so that 2009 emissions from Canal (now all oil-fired) and Salem Harbor (about half oil-fired) could be substantially lower than estimated above.
"Waste-to-energy" plants pay little for the material they burn; petroleum markets have minor effects on their operation. Coal-fired plants will otherwise continue for the foreseeable future to have the lowest fuel costs. Power-plant operators may propose changing from other fuels to coal. That was the course taken by New England Power in 1979, when it obtained an EPA waiver to convert three Brayton Point units from oil-fired to coal-fired. NEP built its own coal transport ship to service Brayton Point. During the 1980s NEP also converted a unit at Salem Harbor. EPA waivers exempted the NEP units from New Source Review requirements of the 1977 Clean Air Act amendments, allowing a pattern of emissions that continued until 2001 changes to Massachusetts requirements.
Coal used at Brayton Point in the five years before it was sold to PG&E in 1997 averaged 0.61 pounds sulfur per million Btu [11], mainly sourced from West Virginia and South America. This represented a significant effort for the time, short of plant remediation. For 1995 West Virginia coal and coal imported to the U.S. averaged 1.19 and 0.56 pounds sulfur per million Btu, respectively [12]. The only large U.S. sources for lower sulfur coal are in Far West states. For 2004 data from the Environmental Protection Agency [1] show sulfur dioxide emitted by Brayton Point equivalent to 0.45 pounds sulfur per million Btu.
At some point in the future, Massachusetts should again review power-plant emission standards, with attention to sulfur dioxide emissions from existing coal-burning and oil-burning plants and attention to nitrogen oxides emissions from existing waste-burning plants.
[1] U.S. Environmental Protection Agency, Emissions and Generation Resource Integrated Database, 2007, www.epa.gov/cleanenergy/egrid/index.htm.
[2] Massachusetts Department of Revenue, Registered Motor Vehicles, 2000-2006, www.mass.gov/Ador/docs/dls/mdmstuf/Socioeconomic/rmv0006.xls.
[3] U.S. Environmental Protection Agency, 2002 National Emissions Inventory, V.3 All Sector Tier Summary, October, 2007 (light-duty automobiles 30,595,547 tons, light duty-trucks 26,343,529 tons),
ftp.epa.gov/EmisInventory/2002finalnei/all_sector_tier_summary_data/tier/02nei_v3tier_summary_oct_15_2007.zip.
[4] U.S. Energy Information Administration, Transportation Energy Consumption Surveys, 2001, Table A1: U.S. Number of Vehicles, Vehicle-Miles, Motor Fuel Consumption and Expenditures, www.eia.doe.gov/emeu/rtecs/nhts_survey/2001/tablefiles/t0464(2005).pdf.
[5] U.S. Department of Commerce, Vehicle Inventory and Use Survey, 1997, www.census.gov/prod/ec97/97tv-us.pdf. 70.8 million registered trucks, 30.0 percent of registered trucks in commercial use, 92.2 percent of trucks light-duty.
[6] U.S. Environmental Protection Agency, Documentation Supplement for EPA Base Case 2003 (V.2.1.6) using the Integrated Planning Model, July, 2003, Attachment O: Fuel Prices, Table O-1, p. O-3, www.epa.gov/airmarkets/progsregs/epa-ipm/docs/attachment-o.pdf.
[7] Platt’s Div. McGraw-Hill, Guide to Petroleum Specifications, 1999, www.emis.platts.com/thezone/guides/platts/oil/oil_specs_1999.pdf.
[8] InflationData.com Div. Capital Professional Services, Historical Crude Oil Prices, 1946-2007, www.inflationdata.com/inflation/inflation_rate/Historical_Oil_Prices_Table.asp.
[9] Chuck Kleekamp, Why oil is on the way out for New England's electric grid, Cape Cod Today, September 21, 2007, www.capecodtoday.com/blogs/index.php/Footnotes/2007/09/21/wind_the_beginning_of_the_end_of_oil_gen.
[10] Jim Polson and Dan Lonkevich, Mirant, a U.S. utility, may seek a buyer, International Herald Tribune, April 10, 2007, www.iht.com/articles/2007/04/10/bloomberg/bxmirant-web.php.
[11] U.S. Energy Information Agency, Coal Transportation Rate Database, 1993-2001, www.eia.doe.gov/cneaf/coal/ctrdb/database.html
[12] U.S. Energy Information Agency, Cost and Quality of Fuels for Electric Utility Plants, 1996 Tables, http://tonto.eia.doe.gov/FTPROOT/electricity/019196.pdf.
Saturday, October 20, 2007
Wednesday, October 17, 2007
Politics of air pollution control, Massachusetts
Environment Massachusetts, part of the Massachusetts Public Interest Research Group, organized a Clean Air coalition in 1997 to reduce emissions from what it called the "filthy five" -- large electricity generation plants in the state. Participants in western Massachusetts soon discovered that MassPIRG had omitted the Mount Tom coal-fired plant run by Holyoke Water Power, perhaps because the U.S. Environmental Protection Agency's 1996 State/Plant Index Page left the name of the facility blank. The "filthy five" became six during a multi-year campaign.
Taking advantage of fractured state politics -- Republican governors since 1991, with Democrats occupying over three-fourths of the legislature, the entire Congressional delegation and a great majority of other offices -- the coalition brought pressure on then-acting Gov. Cellucci. Cellucci ordered a review of power-plant emission standards. A Cellucci administration statement in June, 1998, estimated that by 2003 actions already underway would reduce nitrogen oxide emissions to 29 percent of 1990 levels and said that new actions could cut 7 more percentage points and could reduce mercury emissions by half. The statement made no estimates for reducing sulfur dioxide, known to be more difficult.
In April, 2001, during the administration of Republican acting Gov. Swift, the state Department of Environmental Protection issued new regulations, setting performance limits that applied to the six major power-plants, at 1.5 lb/MWh for nitrogen oxides and 3.0 lb/MWh for sulfur dioxide. Future action was promised on limits for mercury, particulates and carbon dioxide. The Clean Air coalition asked for stricter standards on nitrogen oxides and sulfur dioxide but did not organize vigorously around a specific proposal. After the April, 2001, regulations it dropped those issues and spent most of its subsequent efforts on carbon dioxide limits.
By 1997 Massachusetts already enjoyed lower power-plant emissions than most of the United States. Fuel shifts from coal to oil and natural gas had eliminated about 60 percent of the nitrogen and sulfur oxide emissions of a decade before. However, no significant improvement had occurred in generators that remained coal-fired. The new Massachusetts regulations would require operators of those units to implement controls. New operating permits for the six major plants were issued in 2002.
The six major plants took different approaches. The Mystic plant in Everett, oldest and largest in the state, had opened as a coal-fired plant in 1943, later converting to oil. It was renovated with natural gas, combined cycle generators. One remaining conventional unit in the plant is fired by oil or natural gas but used only during peak demands, since it has lower efficiency. Once a very dirty plant, Mystic now has the state's highest fuel efficiency and best emission performance. The Canal plant in Sandwich, currently all oil-fired, continues to operate much as before, with some added controls to reduce nitrogen oxides.
The four other plants remain mainly coal-fired, with two of them using partly oil to reduce their emissions. The Somerset plant, which has been using partly oil, is installing coal gasification, expected to provide high efficiency and low emissions of nitrogen and sulfur oxides while burning all coal. The Brayton Point plant, also in Somerset and second largest in the state, is installing enough emission controls to meet its requirements but no more. Only part of its equipment is being upgraded. The Salem plant has been in and out of bankruptcy but is now being outfitted to meet requirements, running partly on oil. The Mount Tom plant in Holyoke is making minor changes, using lower-sulfur coal and purchasing emission allocations to meet requirements.
Final permit requirements for nitrogen oxides and sulfur dioxide begin in October, 2008, and it will take two to three years after that before data become available for operations and emissions. However, one can estimate 2009 emissions and examine data for 2004 which have recently been released. They can be compared to performance of new coal-fired plants, which has evolved under the Best Available Control Technologies standard specified by the federal Clean Air Act of 1990. A 2007 draft permit from Arkansas [1] for a new 616 MW coal-fired plant proposed in Hempstead County provides a current, practical example of emissions under the BACT standard.
Annual emissions and electricity generation for the 1999-2001 period and for 2004 are from records of the U.S. Environmental Protection Agency [2]. Estimates for 2009 and for plants of the Hempstead County design are based on generation levels of the six Massachusetts power-plants in 2004, using for 2009 the maximum Massachusetts emission permit levels. Actual emissions for 2009 might be lower because of technologies at the Mystic, Canal and Somerset plants, but since other plants are able to purchase sulfur dioxide allowances from them instead of making reductions, permit levels probably provide realistic estimates.
Basing its approach on its knowledge from the late 1990s, Massachusetts demanded and already has partly achieved emission reductions for six major power-plants. By October, 2008, nitrogen oxide emissions are estimated to be reduced 39 percent and sulfur dioxide emissions are estimated to be reduced 66 percent below the 1999-2001 levels, just before new regulations. However, if Massachusetts standards matched those of the recent Hempstead County permit in Arkansas, both types of emissions in October, 2008, would be about one-fourth as much as the emissions now estimated. Massachusetts is making significant progress, but the state falls well short of Best Available Control Technology for new coal-fired power-plants.
Should Massachusetts have waited before acting? Clean Air coalition participants would likely say no. Political activists engage in causes when they think they can win, not when other conditions are optimum. Massachusetts might still have set more stringent standards. In 1999 the Clinton administration began to file lawsuits against power-plant operators who were skirting New Source Review under the Clean Air Act amendments of 1977 by making incremental improvements to existing plants. See "Legal victories for cleaner power," October 9, 2007.
The first settlements were announced in 2000 with Tampa Electric and Cinergy, but information made available that year [3] did not provide enough detail to guide regulations. The next Clean Air Act settlement [4], announced in January, 2001, showed it was practical for a utility to reduce nitrogen oxide emissions from coal-fired plants by 80 percent and sulfur dioxide emissions by 90 percent. The Massachusetts explanations for new regulations [5] fail to mention any of these events. That may not be surprising. Federal Clean Air Act settlements were late products of a Democratic administration. Massachusetts regulations were products of Republican administrations reacting to political pressure. Since the Clean Air Act of 1970, air pollution control has been influenced at least as much by politics as by technology.
[1] Arkansas Department of Environmental Quality, July, 2007, Draft Operating Air Permit 2123-AOP-R0, www.adeq.state.ar.us/ftproot/Pub/WebDatabases/PermitsOnline/AirDrafts/2123-AOP-R0.pdf. See p. 29.
[2] U.S. Environmental Protection Agency, Emissions and Generation Resource Integrated Database, 2007, www.epa.gov/cleanenergy/egrid/index.htm.
[3] U.S. Energy Information Administration, December, 2000, Analysis of Strategies for Reducing Multiple Emissions from Power Plants: Sulfur Dioxide, Nitrogen Oxides, and Carbon Dioxide, Report SR/OIAF/2000-05, www.eia.doe.gov/oiaf/servicerpt/powerplants/pdf/sroiaf(2000)05.pdf.
[4] U.S. Environmental Protection Agency, January 24, 2001, United States and New Jersey Announce Clean Air Act Coal-Fired Power Plant Settlement with PSEG Fossil, http://yosemite.epa.gov/opa/admpress.nsf/8a769d49720b9912852572a000650c00/1283292799e451fd85256b4b005f4633!OpenDocument.
[5] Massachusetts Department of Environmental Protection, April, 2001, Statement of Reasons and Response to Comments for 310 CMR 7.29, Emission Standards for Power Plants, www.mass.gov/dep/air/laws/finalrsn.doc.
Taking advantage of fractured state politics -- Republican governors since 1991, with Democrats occupying over three-fourths of the legislature, the entire Congressional delegation and a great majority of other offices -- the coalition brought pressure on then-acting Gov. Cellucci. Cellucci ordered a review of power-plant emission standards. A Cellucci administration statement in June, 1998, estimated that by 2003 actions already underway would reduce nitrogen oxide emissions to 29 percent of 1990 levels and said that new actions could cut 7 more percentage points and could reduce mercury emissions by half. The statement made no estimates for reducing sulfur dioxide, known to be more difficult.
In April, 2001, during the administration of Republican acting Gov. Swift, the state Department of Environmental Protection issued new regulations, setting performance limits that applied to the six major power-plants, at 1.5 lb/MWh for nitrogen oxides and 3.0 lb/MWh for sulfur dioxide. Future action was promised on limits for mercury, particulates and carbon dioxide. The Clean Air coalition asked for stricter standards on nitrogen oxides and sulfur dioxide but did not organize vigorously around a specific proposal. After the April, 2001, regulations it dropped those issues and spent most of its subsequent efforts on carbon dioxide limits.
By 1997 Massachusetts already enjoyed lower power-plant emissions than most of the United States. Fuel shifts from coal to oil and natural gas had eliminated about 60 percent of the nitrogen and sulfur oxide emissions of a decade before. However, no significant improvement had occurred in generators that remained coal-fired. The new Massachusetts regulations would require operators of those units to implement controls. New operating permits for the six major plants were issued in 2002.
The six major plants took different approaches. The Mystic plant in Everett, oldest and largest in the state, had opened as a coal-fired plant in 1943, later converting to oil. It was renovated with natural gas, combined cycle generators. One remaining conventional unit in the plant is fired by oil or natural gas but used only during peak demands, since it has lower efficiency. Once a very dirty plant, Mystic now has the state's highest fuel efficiency and best emission performance. The Canal plant in Sandwich, currently all oil-fired, continues to operate much as before, with some added controls to reduce nitrogen oxides.
The four other plants remain mainly coal-fired, with two of them using partly oil to reduce their emissions. The Somerset plant, which has been using partly oil, is installing coal gasification, expected to provide high efficiency and low emissions of nitrogen and sulfur oxides while burning all coal. The Brayton Point plant, also in Somerset and second largest in the state, is installing enough emission controls to meet its requirements but no more. Only part of its equipment is being upgraded. The Salem plant has been in and out of bankruptcy but is now being outfitted to meet requirements, running partly on oil. The Mount Tom plant in Holyoke is making minor changes, using lower-sulfur coal and purchasing emission allocations to meet requirements.
Final permit requirements for nitrogen oxides and sulfur dioxide begin in October, 2008, and it will take two to three years after that before data become available for operations and emissions. However, one can estimate 2009 emissions and examine data for 2004 which have recently been released. They can be compared to performance of new coal-fired plants, which has evolved under the Best Available Control Technologies standard specified by the federal Clean Air Act of 1990. A 2007 draft permit from Arkansas [1] for a new 616 MW coal-fired plant proposed in Hempstead County provides a current, practical example of emissions under the BACT standard.
Annual emissions and electricity generation for the 1999-2001 period and for 2004 are from records of the U.S. Environmental Protection Agency [2]. Estimates for 2009 and for plants of the Hempstead County design are based on generation levels of the six Massachusetts power-plants in 2004, using for 2009 the maximum Massachusetts emission permit levels. Actual emissions for 2009 might be lower because of technologies at the Mystic, Canal and Somerset plants, but since other plants are able to purchase sulfur dioxide allowances from them instead of making reductions, permit levels probably provide realistic estimates.
Basing its approach on its knowledge from the late 1990s, Massachusetts demanded and already has partly achieved emission reductions for six major power-plants. By October, 2008, nitrogen oxide emissions are estimated to be reduced 39 percent and sulfur dioxide emissions are estimated to be reduced 66 percent below the 1999-2001 levels, just before new regulations. However, if Massachusetts standards matched those of the recent Hempstead County permit in Arkansas, both types of emissions in October, 2008, would be about one-fourth as much as the emissions now estimated. Massachusetts is making significant progress, but the state falls well short of Best Available Control Technology for new coal-fired power-plants.
Should Massachusetts have waited before acting? Clean Air coalition participants would likely say no. Political activists engage in causes when they think they can win, not when other conditions are optimum. Massachusetts might still have set more stringent standards. In 1999 the Clinton administration began to file lawsuits against power-plant operators who were skirting New Source Review under the Clean Air Act amendments of 1977 by making incremental improvements to existing plants. See "Legal victories for cleaner power," October 9, 2007.
The first settlements were announced in 2000 with Tampa Electric and Cinergy, but information made available that year [3] did not provide enough detail to guide regulations. The next Clean Air Act settlement [4], announced in January, 2001, showed it was practical for a utility to reduce nitrogen oxide emissions from coal-fired plants by 80 percent and sulfur dioxide emissions by 90 percent. The Massachusetts explanations for new regulations [5] fail to mention any of these events. That may not be surprising. Federal Clean Air Act settlements were late products of a Democratic administration. Massachusetts regulations were products of Republican administrations reacting to political pressure. Since the Clean Air Act of 1970, air pollution control has been influenced at least as much by politics as by technology.
[1] Arkansas Department of Environmental Quality, July, 2007, Draft Operating Air Permit 2123-AOP-R0, www.adeq.state.ar.us/ftproot/Pub/WebDatabases/PermitsOnline/AirDrafts/2123-AOP-R0.pdf. See p. 29.
[2] U.S. Environmental Protection Agency, Emissions and Generation Resource Integrated Database, 2007, www.epa.gov/cleanenergy/egrid/index.htm.
[3] U.S. Energy Information Administration, December, 2000, Analysis of Strategies for Reducing Multiple Emissions from Power Plants: Sulfur Dioxide, Nitrogen Oxides, and Carbon Dioxide, Report SR/OIAF/2000-05, www.eia.doe.gov/oiaf/servicerpt/powerplants/pdf/sroiaf(2000)05.pdf.
[4] U.S. Environmental Protection Agency, January 24, 2001, United States and New Jersey Announce Clean Air Act Coal-Fired Power Plant Settlement with PSEG Fossil, http://yosemite.epa.gov/opa/admpress.nsf/8a769d49720b9912852572a000650c00/1283292799e451fd85256b4b005f4633!OpenDocument.
[5] Massachusetts Department of Environmental Protection, April, 2001, Statement of Reasons and Response to Comments for 310 CMR 7.29, Emission Standards for Power Plants, www.mass.gov/dep/air/laws/finalrsn.doc.
Sunday, October 14, 2007
Fire and brimstone, taming energy
Literary linkage of fire and brimstone, passed on through the Bible (Genesis 19: 24), was not accidental. Sulfur dioxide, the gas from burning brimstone, has long been a dark cloud of energy. Plants take up sulfur from soils, and the burning of plant materials oxidizes the sulfur and releases it to the atmosphere. Most fossil fuels concentrate sulfur from their original plant materials.
When burned, sulfur is mainly converted to sulfur dioxide, which causes lung irritation and long-term health problems. Sulfur dioxide can be transported in the atmosphere over long distances. Gradually it further oxidizes to sulfur trioxide, which then readily combines with water droplets to make sulfuric acid, the main component of acid rain. In that form, sulfur oxides have poisoned thousands of United States water bodies and forest areas.
Burning of fossil fuels for energy produces more than 80 percent of the atmospheric sulfur dioxide in the United States. U.S. coals contain about 0.5 to 6 weight percent sulfur, with concentrations highest in the Midwest and lowest in the far West. Crude petroleum typically contains 0.2 to 3 weight percent sulfur. Average sulfur content of crude petroleum refined in the United States has been gradually increasing and is now about 1.5 percent.
Before the 1980s U.S. coal was burned as mined except for washing to remove stones, with nearly all its sulfur released to the atmosphere. Some of the sulfur in "sour" crude petroleum was removed by refineries, but light refined fuel grades with up to one percent sulfur were common, and some heavy residual fuel grades contained up to three percent. A history of sulfur dioxide emissions is largely a history of the use of coal, influenced somewhat by the use of petroleum and by industrial processes, notably metal smelting.*
Historical growth in U.S. sulfur dioxide emissions began during the 1870s when industries increased use of coal power. Emissions fell when the Great Depression of the 1930s cut back industrial activity, but they rose rapidly during World War II. During the decade after the war, 1945 to 1955, many residential and industrial coal furnaces were converted to use oil or gas, and the railroads replaced their remaining coal-steam locomotives with diesel-electric locomotives, causing sulfur dioxide emissions to fall. After that pause, emissions again rose rapidly as post-war prosperity stimulated the use of electricity, still largely fueled by coal but also, from the 1950s until the oil-price shocks of the 1970s, by high-sulfur residual oil.
The key change in reversing a long-term U.S. trend of sulfur dioxide emissions was the federal Clean Air Act of 1970 (PL 91-604), setting goals for stationary source performance and for motor vehicle pollution reduction and establishing the Environmental Protection Agency. Chief architect of the 1970 act was Sen. Edmund S. Muskie (1914-1996), Democrat of Maine, then Chair of the Senate Public Works Committee. Predecessor legislation included the Clean Air Act of 1955 (PL 84-159), the Clean Air Act of 1963 (PL 88-206) and the Air Quality Act of 1967 (PL 90-148). National Ambient Air Quality Standards set by the Environmental Protection Agency under the 1970 Clear Air Act in turn provoked state efforts that began a reduction in sulfur dioxide emissions.
As with older legislation, the Clean Air Act of 1970 left many responsibilities for achieving air quality to the states, and the effectiveness of state programs varied. Sulfur dioxide reductions of the 1970s and 1980s were mostly achieved by fuel substitution, particularly the use of low-sulfur coal. Regulations limiting sulfur content of fuels for highway uses were also left to state programs, most requiring 0.5 percent sulfur or less, but no regulations limited off-road, railroad or marine fuels. New power-plants were required to meet emission standards, but existing plants were not.
Amendments to the Clean Air Act in 1977 (PL 95-95) relaxed and stretched out some requirements for automobiles but also introduced "Prevention of Significant Deterioration" requirements for areas where air quality meets standards and "New Source Review" requirements for upgrades to power-plants. Improvements beyond routine maintenance were to include upgrades to meet emission standards. Some plant operators began making improvements in increments, each described as routine maintenance. By 1990 federal and state efforts had reduced sulfur dioxide emissions to about 75 percent of the historical peak in 1970, but they were failing to achieve much continued progress.
The federal Clean Air Act of 1990 (PL 101-549) introduced more stringent standards and new goals. Acid rain was recognized as a multistate issue, beyond the reach of a single state, and regional control efforts were authorized. A "cap and trade" program required monitoring of emissions and allowed power-plant operators to choose between reducing emissions and purchasing unused emission allocations from other power-plants.
During five years of a so-called "Phase I" 110 large emission sources were targeted by the 1990 law, and during a subsequent "Phase II" all stationary sources with 25 MW or larger electrical capacity were affected. The new law required implementation of "Best Available Control Technology" and set a national goal of 40 percent reduction below 1980 levels for stationary source emissions, to be achieved within ten years. The law also authorized new standards for mobile sources, eventually affecting all highway petroleum fuels as well as off-road, railroad and marine fuels.
The 1990 act stimulated installation of flue gas scrubbers, the best available technology developed since the 1970 act. The most effective units use water-activated lime, magnesia or soda -- usually lime -- that combines with sulfur dioxide and removes it. Current state-of-the-art scrubbers capture 90 to 95 percent of sulfur dioxide emissions, and some produce recyclable byproducts, typically gypsum for wallboard and other building products. Advanced dry-process technologies have approached wet-process effectiveness for sulfur dioxide capture and may have advantages for removal of other pollutants, but they do not produce recyclable byproducts.
The substantial costs of installing and operating scrubbers were resisted by most power-plant operators. By the mid-1990s they were competing in a deregulated economy and could no longer count on electricity rates that would compensate for their costs. Recognizing the patterns of resistance, including incremental plant improvements to skirt New Source Review, starting in 1999 the Clinton administration filed legal complaints against several major power-plant operators, seeking compliance with standards.
As of fall, 2007, we are still in the downdraft of changes inspired by the 1990 Clean Air Act. The law's sulfur dioxide emissions goal for the year 2000 was achieved by 2003. Most of the Clinton administration lawsuits have been settled with major emission reductions, although some remain open. The lawsuits prolonged and deepened trends in this stage of reductions. A look at the trends shows that U.S. sulfur dioxide emissions have reached levels of about 100 years earlier and may go below 10 million tons of sulfur dioxide per year some time between 2015 and 2020, last seen at the end of the 1900s.
Should there be a new effort? Should we try to extend progress and achieve emission levels found only before the development of heavy industries? While further power-plant upgrades might take us that far, we are engaged with another long-term concern: control of greenhouse gas emissions, principally carbon dioxide and methane. Mining and burning coal emits more greenhouse gases than any other technology for generating electricity. As we replace coal with solar, wind or nuclear technology, lower sulfur dioxide emissions will follow.
* Sources for U.S. sulfur dioxide emissions
1990-2005: U.S. Environmental Protection Agency, U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, April 15, 2007, Annex Table A-236, pp. A-290 and A-291, www.epa.gov/climatechange/emissions/downloads06/07AllAnnexes.pdf.
1970-1985: U.S. Environmental Protection Agency, National Air Quality and Emissions Trends Report, 1999, Data Tables, Table A-8, pp. 153-155, www.epa.gov/air/airtrends/aqtrnd99/pdfs/Appena.pdf.
1900-1965: Rudolf B. Husar, Sulfur and Nitrogen Emission Trends for the U.S., Center for Air Pollution Impact and Trend Analysis, Washington University, St. Louis, 1992, http://capita.wustl.edu/capita/CapitaReports/EmisTrends/soxnem.html.
Also see: S.J. Smith, E. Conception, R. Andres and J. Lurz, Historical Sulfur Dioxide Emissions 1850-2000: Methods and Results, Pacific Northwest National Laboratory Report PNNL-14537, January, 2004, www.pnl.gov/main/publications/external/technical_reports/PNNL-14537.pdf.
When burned, sulfur is mainly converted to sulfur dioxide, which causes lung irritation and long-term health problems. Sulfur dioxide can be transported in the atmosphere over long distances. Gradually it further oxidizes to sulfur trioxide, which then readily combines with water droplets to make sulfuric acid, the main component of acid rain. In that form, sulfur oxides have poisoned thousands of United States water bodies and forest areas.
Burning of fossil fuels for energy produces more than 80 percent of the atmospheric sulfur dioxide in the United States. U.S. coals contain about 0.5 to 6 weight percent sulfur, with concentrations highest in the Midwest and lowest in the far West. Crude petroleum typically contains 0.2 to 3 weight percent sulfur. Average sulfur content of crude petroleum refined in the United States has been gradually increasing and is now about 1.5 percent.
Before the 1980s U.S. coal was burned as mined except for washing to remove stones, with nearly all its sulfur released to the atmosphere. Some of the sulfur in "sour" crude petroleum was removed by refineries, but light refined fuel grades with up to one percent sulfur were common, and some heavy residual fuel grades contained up to three percent. A history of sulfur dioxide emissions is largely a history of the use of coal, influenced somewhat by the use of petroleum and by industrial processes, notably metal smelting.*
Historical growth in U.S. sulfur dioxide emissions began during the 1870s when industries increased use of coal power. Emissions fell when the Great Depression of the 1930s cut back industrial activity, but they rose rapidly during World War II. During the decade after the war, 1945 to 1955, many residential and industrial coal furnaces were converted to use oil or gas, and the railroads replaced their remaining coal-steam locomotives with diesel-electric locomotives, causing sulfur dioxide emissions to fall. After that pause, emissions again rose rapidly as post-war prosperity stimulated the use of electricity, still largely fueled by coal but also, from the 1950s until the oil-price shocks of the 1970s, by high-sulfur residual oil.
The key change in reversing a long-term U.S. trend of sulfur dioxide emissions was the federal Clean Air Act of 1970 (PL 91-604), setting goals for stationary source performance and for motor vehicle pollution reduction and establishing the Environmental Protection Agency. Chief architect of the 1970 act was Sen. Edmund S. Muskie (1914-1996), Democrat of Maine, then Chair of the Senate Public Works Committee. Predecessor legislation included the Clean Air Act of 1955 (PL 84-159), the Clean Air Act of 1963 (PL 88-206) and the Air Quality Act of 1967 (PL 90-148). National Ambient Air Quality Standards set by the Environmental Protection Agency under the 1970 Clear Air Act in turn provoked state efforts that began a reduction in sulfur dioxide emissions.
As with older legislation, the Clean Air Act of 1970 left many responsibilities for achieving air quality to the states, and the effectiveness of state programs varied. Sulfur dioxide reductions of the 1970s and 1980s were mostly achieved by fuel substitution, particularly the use of low-sulfur coal. Regulations limiting sulfur content of fuels for highway uses were also left to state programs, most requiring 0.5 percent sulfur or less, but no regulations limited off-road, railroad or marine fuels. New power-plants were required to meet emission standards, but existing plants were not.
Amendments to the Clean Air Act in 1977 (PL 95-95) relaxed and stretched out some requirements for automobiles but also introduced "Prevention of Significant Deterioration" requirements for areas where air quality meets standards and "New Source Review" requirements for upgrades to power-plants. Improvements beyond routine maintenance were to include upgrades to meet emission standards. Some plant operators began making improvements in increments, each described as routine maintenance. By 1990 federal and state efforts had reduced sulfur dioxide emissions to about 75 percent of the historical peak in 1970, but they were failing to achieve much continued progress.
The federal Clean Air Act of 1990 (PL 101-549) introduced more stringent standards and new goals. Acid rain was recognized as a multistate issue, beyond the reach of a single state, and regional control efforts were authorized. A "cap and trade" program required monitoring of emissions and allowed power-plant operators to choose between reducing emissions and purchasing unused emission allocations from other power-plants.
During five years of a so-called "Phase I" 110 large emission sources were targeted by the 1990 law, and during a subsequent "Phase II" all stationary sources with 25 MW or larger electrical capacity were affected. The new law required implementation of "Best Available Control Technology" and set a national goal of 40 percent reduction below 1980 levels for stationary source emissions, to be achieved within ten years. The law also authorized new standards for mobile sources, eventually affecting all highway petroleum fuels as well as off-road, railroad and marine fuels.
The 1990 act stimulated installation of flue gas scrubbers, the best available technology developed since the 1970 act. The most effective units use water-activated lime, magnesia or soda -- usually lime -- that combines with sulfur dioxide and removes it. Current state-of-the-art scrubbers capture 90 to 95 percent of sulfur dioxide emissions, and some produce recyclable byproducts, typically gypsum for wallboard and other building products. Advanced dry-process technologies have approached wet-process effectiveness for sulfur dioxide capture and may have advantages for removal of other pollutants, but they do not produce recyclable byproducts.
The substantial costs of installing and operating scrubbers were resisted by most power-plant operators. By the mid-1990s they were competing in a deregulated economy and could no longer count on electricity rates that would compensate for their costs. Recognizing the patterns of resistance, including incremental plant improvements to skirt New Source Review, starting in 1999 the Clinton administration filed legal complaints against several major power-plant operators, seeking compliance with standards.
As of fall, 2007, we are still in the downdraft of changes inspired by the 1990 Clean Air Act. The law's sulfur dioxide emissions goal for the year 2000 was achieved by 2003. Most of the Clinton administration lawsuits have been settled with major emission reductions, although some remain open. The lawsuits prolonged and deepened trends in this stage of reductions. A look at the trends shows that U.S. sulfur dioxide emissions have reached levels of about 100 years earlier and may go below 10 million tons of sulfur dioxide per year some time between 2015 and 2020, last seen at the end of the 1900s.
Should there be a new effort? Should we try to extend progress and achieve emission levels found only before the development of heavy industries? While further power-plant upgrades might take us that far, we are engaged with another long-term concern: control of greenhouse gas emissions, principally carbon dioxide and methane. Mining and burning coal emits more greenhouse gases than any other technology for generating electricity. As we replace coal with solar, wind or nuclear technology, lower sulfur dioxide emissions will follow.
* Sources for U.S. sulfur dioxide emissions
1990-2005: U.S. Environmental Protection Agency, U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, April 15, 2007, Annex Table A-236, pp. A-290 and A-291, www.epa.gov/climatechange/emissions/downloads06/07AllAnnexes.pdf.
1970-1985: U.S. Environmental Protection Agency, National Air Quality and Emissions Trends Report, 1999, Data Tables, Table A-8, pp. 153-155, www.epa.gov/air/airtrends/aqtrnd99/pdfs/Appena.pdf.
1900-1965: Rudolf B. Husar, Sulfur and Nitrogen Emission Trends for the U.S., Center for Air Pollution Impact and Trend Analysis, Washington University, St. Louis, 1992, http://capita.wustl.edu/capita/CapitaReports/EmisTrends/soxnem.html.
Also see: S.J. Smith, E. Conception, R. Andres and J. Lurz, Historical Sulfur Dioxide Emissions 1850-2000: Methods and Results, Pacific Northwest National Laboratory Report PNNL-14537, January, 2004, www.pnl.gov/main/publications/external/technical_reports/PNNL-14537.pdf.
Friday, October 12, 2007
Chevrolet Volt, an environmental makeover
If energy for an electric vehicle is supplied by renewable sources, greenhouse gas emissions are low. What would that cost? Prices for photovoltaic (PV) solar panels have been steadily dropping for many years, although recently prices have firmed because of heavy demand in Europe. A practical approach could use fixed-mount PV panels to supply daily energy to the electrical grid equal to the energy needed on workdays to power the vehicle.
The following analysis focuses on installing PV panels to supply the energy for a Chevrolet Volt, as used for workday commuting, providing enough low-pollution, renewable energy to replace high-pollution energy from the electrical grid. See "Chevrolet Volt, a plug-in polluter," September 27, 2007. The grid is fed during the day by solar power and tapped at night to charge batteries, a beneficial offset to the typical patterns of grid activity.
Chevrolet Volt electricity use, at 10,000 mile/year --
-- 14 kWh/workday * 240 workdays/year = 3360 kWh/year
Practical utilization factor for fixed-mount PV installation --
-- Applied Materials, Sunnyvale, CA, March 14, 2007, via WebWire
-- www.webwire.com/ViewPressRel.asp?aId=29293
-- 2300 MWh / (1.9 MW * 8760 hr) = 0.138 utilization factor
Nameplate PV system power rating, fixed-mount installation --
-- 3360 kWh/year / (8760 hr/year * 0.138 utilization factor) = 2.8 kW AC
Configured cost, 3.15 kW DC nameplate PV and inverter connector, $17,494 --
-- October, 2007, California, Solatron, www.partsonsale.com
-- 5% inverter loss and 5% lower tolerance leaves minimum 2.8 kW AC
Mortgage rates, 30-year fixed, national average, 6.1 percent --
-- October, 2007, www.bankrate.com/brm/publ/30yrmolg.asp
-- monthly mortgage payment for $17,494 initial principal, $106.01
Annual capital cost of PV energy for Chevrolet Volt --
-- $106 per month * 12 months = $1,272
Annual cost of gasoline for Chevrolet Volt --
-- $2.45 per workday * 240 workdays = $588
Annual cost of electrical grid energy for Chevrolet Volt --
-- $1.55 per workday * 240 workdays = $372
This simplified analysis assumes no system maintenance costs, no charges for occupancy of land, no installation or mortgage closing costs, and no credit for nighttime electricity used from the grid versus daytime energy supplied to the grid. On such a basis, photovoltaic energy cost will be about 2.2 times the cost of gasoline. The installed cost of an adequate photovoltaic system is a substantial fraction of the cost of the vehicle. That is a social view of costs, while a consumer's view is influenced by opportunities for government subsidies and tax avoidance.
In California, a combination of state and federal subsidies would reduce consumer cost of the photovoltaic system to about $8,441, bringing the estimated cost of photovoltaic energy down to $614 per year. With government subsidies paying for near half of the photovoltaic system and with consumers paying no gasoline taxes to support highway maintenance, a Chevrolet Volt's cost for low-pollution photovoltaic energy becomes little different from its cost for gasoline and only modestly higher than its cost for high-pollution energy from the electrical grid.
Other practical issues with photovoltaics should be considered. The system used as an example involves an array of panels about five feet high and fifty feet long. For rated performance, the panels need to be mounted at an angle within 10 degrees of perpendicular to the average sun direction over the year. Many houses lack enough roof space, or they have unfavorable orientations. Few if any multifamily apartments have enough space. Widespread substitution of photovoltaic energy for electrical grid energy will require community or regional facilities.
The following analysis focuses on installing PV panels to supply the energy for a Chevrolet Volt, as used for workday commuting, providing enough low-pollution, renewable energy to replace high-pollution energy from the electrical grid. See "Chevrolet Volt, a plug-in polluter," September 27, 2007. The grid is fed during the day by solar power and tapped at night to charge batteries, a beneficial offset to the typical patterns of grid activity.
Chevrolet Volt electricity use, at 10,000 mile/year --
-- 14 kWh/workday * 240 workdays/year = 3360 kWh/year
Practical utilization factor for fixed-mount PV installation --
-- Applied Materials, Sunnyvale, CA, March 14, 2007, via WebWire
-- www.webwire.com/ViewPressRel.asp?aId=29293
-- 2300 MWh / (1.9 MW * 8760 hr) = 0.138 utilization factor
Nameplate PV system power rating, fixed-mount installation --
-- 3360 kWh/year / (8760 hr/year * 0.138 utilization factor) = 2.8 kW AC
Configured cost, 3.15 kW DC nameplate PV and inverter connector, $17,494 --
-- October, 2007, California, Solatron, www.partsonsale.com
-- 5% inverter loss and 5% lower tolerance leaves minimum 2.8 kW AC
Mortgage rates, 30-year fixed, national average, 6.1 percent --
-- October, 2007, www.bankrate.com/brm/publ/30yrmolg.asp
-- monthly mortgage payment for $17,494 initial principal, $106.01
Annual capital cost of PV energy for Chevrolet Volt --
-- $106 per month * 12 months = $1,272
Annual cost of gasoline for Chevrolet Volt --
-- $2.45 per workday * 240 workdays = $588
Annual cost of electrical grid energy for Chevrolet Volt --
-- $1.55 per workday * 240 workdays = $372
This simplified analysis assumes no system maintenance costs, no charges for occupancy of land, no installation or mortgage closing costs, and no credit for nighttime electricity used from the grid versus daytime energy supplied to the grid. On such a basis, photovoltaic energy cost will be about 2.2 times the cost of gasoline. The installed cost of an adequate photovoltaic system is a substantial fraction of the cost of the vehicle. That is a social view of costs, while a consumer's view is influenced by opportunities for government subsidies and tax avoidance.
In California, a combination of state and federal subsidies would reduce consumer cost of the photovoltaic system to about $8,441, bringing the estimated cost of photovoltaic energy down to $614 per year. With government subsidies paying for near half of the photovoltaic system and with consumers paying no gasoline taxes to support highway maintenance, a Chevrolet Volt's cost for low-pollution photovoltaic energy becomes little different from its cost for gasoline and only modestly higher than its cost for high-pollution energy from the electrical grid.
Other practical issues with photovoltaics should be considered. The system used as an example involves an array of panels about five feet high and fifty feet long. For rated performance, the panels need to be mounted at an angle within 10 degrees of perpendicular to the average sun direction over the year. Many houses lack enough roof space, or they have unfavorable orientations. Few if any multifamily apartments have enough space. Widespread substitution of photovoltaic energy for electrical grid energy will require community or regional facilities.
Tuesday, October 9, 2007
Legal victories for cleaner power
Under the Walker Bush administration, the federal Environmental Protection Agency (EPA) weakened power-plant emission standards by allowing more renovations at older plants without satisfying standards. However, it also continued some enforcement actions that were started during the Clinton administration, only to be blocked by adverse rulings from southern federal court jurisdictions. Those misfortunes ended with a unanimous Supreme Court decision April 2, 2007, in Environmental Defense v. Duke Energy, reversing lower court rulings. Most issues now fall back to review by the EPA. On April 24, 2007, EPA moved to undercut the Supreme Court decision by further weakening its power-plant standards, changing the criterion for enforcement from annual to hourly emissions.
Large power-plant operators have taken notice. In another of the Clinton administration cases, United States v. American Electric Power (AEP), a settlement was announced October 8, 2007, one day before a scheduled district court hearing related to the trial held in July, 2005. Choosing to settle the case rather than risk a verdict that might have cost it more, AEP of Columbus, OH, the largest U.S. operator of coal-fired power-plants, agreed to spend an estimated $4.6 billion on plant upgrades to cut emissions. When the legal complaint was filed in 1999 AEP stated, "This lawsuit is just another political effort...totally without merit." The EPA complaint said AEP violated emission standards at 30 of its 46 coal-fired units.
Under terms of the settlement, AEP is to reduce nitrogen oxide emissions by 69 percent (to 72,000 tons per year) by 2016 and to reduce sulfur dioxide emissions by 79 percent (to 174,000 tons per year) by 2018. A statement from the U.S. Department of Justice estimated annual benefits at $32 billion per year saved in health-related costs associated with respiratory and cardiopulmonary illnesses. EPA assistant administrator Granta Nakayama said air pollution reductions from the settlement substantially exceed those from all EPA enforcement actions in the previous three years. The 1967 federal Air Quality Act, now called the Clean Air Act, authorizes penalties up to $27,500 per plant per day for violations.
The AEP consent decree sets total annual emission limits for the 46 AEP generating units in Ohio, West Virginia, Indiana, Kentucky and Virginia. It also sets individual unit operating limits for nitrogen oxides and sulfur dioxide, both 0.10 pounds per million BTU heat input. By comparison, EPA operating limits for new generating plants are 0.11 pounds nitrogen oxides and 0.15 pounds sulfur dioxide per million BTU heat input. New generating plants, however, are also subject to performance limits based on amounts of electricity generated and to limits for other pollutants, including mercury and soot. Lack of performance limits in the AEP settlement might encourage AEP to continue using inefficient technology, but AEP has announced plans to upgrade some steam turbines to improve efficiency.
The lawsuits filed during the Clinton administration, mostly in November, 1999, were the first enforcement actions since 1977 Clean Air Act amendments requiring plants undergoing renovation to meet emission standards. Many plants were upgraded incrementally without meeting standards. Lawsuits against Cinergy, Teco (Tampa Electric), Vectren (Southern Indiana Gas & Electric), Dynegy (Illinois Power), FirstEnergy (Ohio Edison) and American Electric Power have been settled with terms requiring major pollution reductions and payments of fines. However, Cinergy, now a subsidiary of Duke Energy, backed away from its negotiated settlement and then lost in a district court trial and a 2006 appeals court ruling.
Clinton administration enforcement actions without lawsuits have been similarly settled by PSEG Fossil, Dominion (Virginia Electric Power) and Wisconsin Electric. A private lawsuit filed in December, 2001, against Alcoa, operator of a power plant in Rockdale, TX, was later joined by EPA and similarly settled. Clinton administration lawsuits remain outstanding involving Duke Energy (Duke Power, Cinergy) and Southern (Alabama Power, Georgia Power). Like AEP, the firms can conclude settlements with EPA or take their chances in a judicial environment that has swung against them.
As a measure of their effectiveness, all Clean Air Act settlements to date combined are estimated to reduce U.S. sulfur dioxide emissions by about 1.64 million tons per year, of which almost half comes from the recent AEP settlement. That is 10.0 percent of the U.S. total emissions in 2000, estimated by EPA at 16.35 million tons per year. By 2005 total U.S. sulfur dioxide emissions had dropped by 1.72 million tons per year. Only a small part the 10.5 percent reduction represents early, direct effects of Clean Air Act settlements, which are now spread over a period of 18 years.
If estimates of health benefits in the AEP case are correct, the federal government could probably have saved enough money in Medicare costs to pay for the pollution control improvements many times over. Studies began to show evidence of environmental and health impacts from power-plant pollution in the 1960s. From early concerns over Midwest power-plant pollution to remediation of the AEP plants will have taken more than fifty years.
Large power-plant operators have taken notice. In another of the Clinton administration cases, United States v. American Electric Power (AEP), a settlement was announced October 8, 2007, one day before a scheduled district court hearing related to the trial held in July, 2005. Choosing to settle the case rather than risk a verdict that might have cost it more, AEP of Columbus, OH, the largest U.S. operator of coal-fired power-plants, agreed to spend an estimated $4.6 billion on plant upgrades to cut emissions. When the legal complaint was filed in 1999 AEP stated, "This lawsuit is just another political effort...totally without merit." The EPA complaint said AEP violated emission standards at 30 of its 46 coal-fired units.
Under terms of the settlement, AEP is to reduce nitrogen oxide emissions by 69 percent (to 72,000 tons per year) by 2016 and to reduce sulfur dioxide emissions by 79 percent (to 174,000 tons per year) by 2018. A statement from the U.S. Department of Justice estimated annual benefits at $32 billion per year saved in health-related costs associated with respiratory and cardiopulmonary illnesses. EPA assistant administrator Granta Nakayama said air pollution reductions from the settlement substantially exceed those from all EPA enforcement actions in the previous three years. The 1967 federal Air Quality Act, now called the Clean Air Act, authorizes penalties up to $27,500 per plant per day for violations.
The AEP consent decree sets total annual emission limits for the 46 AEP generating units in Ohio, West Virginia, Indiana, Kentucky and Virginia. It also sets individual unit operating limits for nitrogen oxides and sulfur dioxide, both 0.10 pounds per million BTU heat input. By comparison, EPA operating limits for new generating plants are 0.11 pounds nitrogen oxides and 0.15 pounds sulfur dioxide per million BTU heat input. New generating plants, however, are also subject to performance limits based on amounts of electricity generated and to limits for other pollutants, including mercury and soot. Lack of performance limits in the AEP settlement might encourage AEP to continue using inefficient technology, but AEP has announced plans to upgrade some steam turbines to improve efficiency.
The lawsuits filed during the Clinton administration, mostly in November, 1999, were the first enforcement actions since 1977 Clean Air Act amendments requiring plants undergoing renovation to meet emission standards. Many plants were upgraded incrementally without meeting standards. Lawsuits against Cinergy, Teco (Tampa Electric), Vectren (Southern Indiana Gas & Electric), Dynegy (Illinois Power), FirstEnergy (Ohio Edison) and American Electric Power have been settled with terms requiring major pollution reductions and payments of fines. However, Cinergy, now a subsidiary of Duke Energy, backed away from its negotiated settlement and then lost in a district court trial and a 2006 appeals court ruling.
Clinton administration enforcement actions without lawsuits have been similarly settled by PSEG Fossil, Dominion (Virginia Electric Power) and Wisconsin Electric. A private lawsuit filed in December, 2001, against Alcoa, operator of a power plant in Rockdale, TX, was later joined by EPA and similarly settled. Clinton administration lawsuits remain outstanding involving Duke Energy (Duke Power, Cinergy) and Southern (Alabama Power, Georgia Power). Like AEP, the firms can conclude settlements with EPA or take their chances in a judicial environment that has swung against them.
As a measure of their effectiveness, all Clean Air Act settlements to date combined are estimated to reduce U.S. sulfur dioxide emissions by about 1.64 million tons per year, of which almost half comes from the recent AEP settlement. That is 10.0 percent of the U.S. total emissions in 2000, estimated by EPA at 16.35 million tons per year. By 2005 total U.S. sulfur dioxide emissions had dropped by 1.72 million tons per year. Only a small part the 10.5 percent reduction represents early, direct effects of Clean Air Act settlements, which are now spread over a period of 18 years.
If estimates of health benefits in the AEP case are correct, the federal government could probably have saved enough money in Medicare costs to pay for the pollution control improvements many times over. Studies began to show evidence of environmental and health impacts from power-plant pollution in the 1960s. From early concerns over Midwest power-plant pollution to remediation of the AEP plants will have taken more than fifty years.
Saturday, October 6, 2007
Magic bullets for electricity miss their marks
Ever since Edison, commercial electric power has been linked with "magic bullets" that could somehow slay one or another economic or environmental dragon. All have missed their marks.
A prediction widely quoted in the 1940s and 1950s from the late Alvin Weinberg, former director of Oak Ridge National Laboratory, said nuclear reactors would produce electricity "too cheap to measure." Like many scientists of his era, Weinberg grossly underestimated the costs of achieving safe operation. As true costs emerged from the late 1960s through the 1970s, prices of nuclear power-plants spiraled and orders dwindled. After the Three Mile Island disaster in 1979 no new orders were placed, and most outstanding orders were cancelled. For about thirty years the U.S. nuclear power industry went into hibernation. Despite billions of dollars and more than four decades of effort, no reliable solution has yet been demonstrated for the long-term storage of nuclear waste.
Commercial electricity has long been promoted as "clean" power, but that can prove true only for people who live far from power-plants. All forms of concentrated energy production present environmental hazards. From the 1880s through the 1940s hydroelectric power was often promoted as an environmental ideal, minimizing its potential to destroy impounded and downstream habitat, devastate fish stocks, and create major hazards from dam collapse. Those concerns caused the Eisenhower administration to stop new commitments for federal dams and reservoirs. Hydroelectric power has remained stagnant since then in the United States, shrinking as a source of electricity from about 35 percent in 1940 to about 10 percent in 2005.
Natural gas has been used for power generation since the 1920s, particularly in the Southwest where, through the 1950s, it was sometimes "flared" as waste. It now dominates plans for new power plants, because permits can be easier to obtain than with other technologies. Saturation of the U.S. domestic supply in the 1970s led to growth of imports, mainly from Canada, Trinidad and Africa. As of 2005 imports totaled about 20 percent of consumption, with about 85 percent of imports coming from Canada. Leveling of Canadian production has led to demand for liquefied natural gas terminals along the coasts. As of 2005, the continental United States had only four such terminals, but applications had been filed for more than twenty new ones. While no major LNG accident has occurred in the U.S. since a Cleveland explosion killed 128 people in 1944, the potential for damage is high. A Sandia study in 2004 found that a major accident could demolish most buildings within a quarter mile and spread fires a mile or more away.
Pollution from coal-fired plants is probably the best known danger from generating electricity. Hazardous trace metals, including mercury, arsenic and cadmium, are deposited downwind. Nitrogen oxides create health hazards from ground-level ozone. Acid rain from sulfur oxides may fall hundreds to thousands of miles away. Coal-fired generators in the Midwest and Southeast have poisoned thousands of water bodies and forest areas across the eastern United States. Burning coal also releases more carbon dioxide and other greenhouse gases per unit electricity than any other technology. Ash dumps provide readily mobilized sources of toxic metals and continue to contaminate water suppplies. In recent years, carbon dioxide sequestration has been proposed in former wells and mines. However, no pilot plant has been built, and no one has been able to prove that buried carbon dioxide will not leak to the atmosphere. The long-term confinement of gaseous pollutants may be as problematic as the long-term confinement of nuclear waste.
Hydrogen has been widely touted as an intermediate to store electrical energy, particularly for transportation. That is its least likely application. If hydrogen cannot be used effectively in stationary settings, where its storage is far easier, it has no future. Current efficiencies for converting electrical energy to and from hydrogen make it far too expensive as an energy reservoir. Since the 1890s the state-of-the-art has been pumped hydroelectric storage, with new systems estimated to recover almost 80 percent of input energy. An emerging competitor is the sodium-sulfur battery, with new units estimated to recover about 75 percent of input energy. The best of the current, practical technologies based on hydrogen recover less than 30 percent of input energy.
Several energy substitution technologies, including heat pumps and electric vehicles, aim to replace petroleum uses with commercial electricity. Promoters of these technologies typically claim that somehow electricity will be supplied with clean, renewable technology, without showing how such an outcome is to be guaranteed. If fact, the most likely results of such schemes are to burn coal instead of petroleum, generating more pollution and releasing more greenhouse gases than before. In the United States, the current lower-pollution sources of electricity, including hydroelectric, nuclear and wind, typically operate near maximum capacity because of costs or regulations. There is no surplus of such power. Growth in renewable sources has been well short of the recent growth in electricity use. Over the next two to three decades, other additions to electricity demands will most often be met by increased output from coal-powered generators, the main sources with current surplus capacity.
Improvements in energy production and use, including electricity, are far from impossible. Their history has shown, however, that improvements occur incrementally over decades. For example, average efficiency of electrical power generation increased by about a factor of six between 1900 and 1950, although the following fifty years saw only about 40 percent further improvement. However, efficiencies of both automobiles and commercial passenger aircraft improved by about a factor of two during fifty years beginning in the late 1950s. A little-known transportation miracle is that fuel consumption per passenger-mile for travel in an average sedan has not matched fuel consumption in a state-of-the-art, fully occupied commercial aircraft, unless an automobile has carried three or more passengers.
A prediction widely quoted in the 1940s and 1950s from the late Alvin Weinberg, former director of Oak Ridge National Laboratory, said nuclear reactors would produce electricity "too cheap to measure." Like many scientists of his era, Weinberg grossly underestimated the costs of achieving safe operation. As true costs emerged from the late 1960s through the 1970s, prices of nuclear power-plants spiraled and orders dwindled. After the Three Mile Island disaster in 1979 no new orders were placed, and most outstanding orders were cancelled. For about thirty years the U.S. nuclear power industry went into hibernation. Despite billions of dollars and more than four decades of effort, no reliable solution has yet been demonstrated for the long-term storage of nuclear waste.
Commercial electricity has long been promoted as "clean" power, but that can prove true only for people who live far from power-plants. All forms of concentrated energy production present environmental hazards. From the 1880s through the 1940s hydroelectric power was often promoted as an environmental ideal, minimizing its potential to destroy impounded and downstream habitat, devastate fish stocks, and create major hazards from dam collapse. Those concerns caused the Eisenhower administration to stop new commitments for federal dams and reservoirs. Hydroelectric power has remained stagnant since then in the United States, shrinking as a source of electricity from about 35 percent in 1940 to about 10 percent in 2005.
Natural gas has been used for power generation since the 1920s, particularly in the Southwest where, through the 1950s, it was sometimes "flared" as waste. It now dominates plans for new power plants, because permits can be easier to obtain than with other technologies. Saturation of the U.S. domestic supply in the 1970s led to growth of imports, mainly from Canada, Trinidad and Africa. As of 2005 imports totaled about 20 percent of consumption, with about 85 percent of imports coming from Canada. Leveling of Canadian production has led to demand for liquefied natural gas terminals along the coasts. As of 2005, the continental United States had only four such terminals, but applications had been filed for more than twenty new ones. While no major LNG accident has occurred in the U.S. since a Cleveland explosion killed 128 people in 1944, the potential for damage is high. A Sandia study in 2004 found that a major accident could demolish most buildings within a quarter mile and spread fires a mile or more away.
Pollution from coal-fired plants is probably the best known danger from generating electricity. Hazardous trace metals, including mercury, arsenic and cadmium, are deposited downwind. Nitrogen oxides create health hazards from ground-level ozone. Acid rain from sulfur oxides may fall hundreds to thousands of miles away. Coal-fired generators in the Midwest and Southeast have poisoned thousands of water bodies and forest areas across the eastern United States. Burning coal also releases more carbon dioxide and other greenhouse gases per unit electricity than any other technology. Ash dumps provide readily mobilized sources of toxic metals and continue to contaminate water suppplies. In recent years, carbon dioxide sequestration has been proposed in former wells and mines. However, no pilot plant has been built, and no one has been able to prove that buried carbon dioxide will not leak to the atmosphere. The long-term confinement of gaseous pollutants may be as problematic as the long-term confinement of nuclear waste.
Hydrogen has been widely touted as an intermediate to store electrical energy, particularly for transportation. That is its least likely application. If hydrogen cannot be used effectively in stationary settings, where its storage is far easier, it has no future. Current efficiencies for converting electrical energy to and from hydrogen make it far too expensive as an energy reservoir. Since the 1890s the state-of-the-art has been pumped hydroelectric storage, with new systems estimated to recover almost 80 percent of input energy. An emerging competitor is the sodium-sulfur battery, with new units estimated to recover about 75 percent of input energy. The best of the current, practical technologies based on hydrogen recover less than 30 percent of input energy.
Several energy substitution technologies, including heat pumps and electric vehicles, aim to replace petroleum uses with commercial electricity. Promoters of these technologies typically claim that somehow electricity will be supplied with clean, renewable technology, without showing how such an outcome is to be guaranteed. If fact, the most likely results of such schemes are to burn coal instead of petroleum, generating more pollution and releasing more greenhouse gases than before. In the United States, the current lower-pollution sources of electricity, including hydroelectric, nuclear and wind, typically operate near maximum capacity because of costs or regulations. There is no surplus of such power. Growth in renewable sources has been well short of the recent growth in electricity use. Over the next two to three decades, other additions to electricity demands will most often be met by increased output from coal-powered generators, the main sources with current surplus capacity.
Improvements in energy production and use, including electricity, are far from impossible. Their history has shown, however, that improvements occur incrementally over decades. For example, average efficiency of electrical power generation increased by about a factor of six between 1900 and 1950, although the following fifty years saw only about 40 percent further improvement. However, efficiencies of both automobiles and commercial passenger aircraft improved by about a factor of two during fifty years beginning in the late 1950s. A little-known transportation miracle is that fuel consumption per passenger-mile for travel in an average sedan has not matched fuel consumption in a state-of-the-art, fully occupied commercial aircraft, unless an automobile has carried three or more passengers.
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